The invention relates to compositions and methods for reducing the permeability of underground strata during secondary recovery of oil.
When an oil well is first drilled, oil will often flow from the well under the natural pressure existing in oil-bearing stratum. When this natural pressure becomes insufficient, further quantities of oil may be recovered from the well by a mechanical pump. However, it is well known to those skilled in the art that even when no more oil can be recovered from the well simply by mechanical pumping, large quantities of oil often still remain in the oil-bearing stratum, especially if the oil is a heavy, viscous type of crude oil. To recover at least part of this residual oil, which will not flow naturally to the bottom of an oil well penetrating the oil-bearing stratum, so-called "secondary" recovery techniques have been developed. In such secondary recovery techniques, a flooding liquid (which may be, for example, water, brine, an aqueous solution of a polymer, an aqueous solution of a surfactant or a hydrocarbon fluid) is pumped down an injector well. The flooding liquid flows from the injector well through the oil-bearing stratum and forces at least part of the residual oil into a producer well. In some cases, it is advantageous to inject steam down the injector well since the resultant heating of the oil-bearing stratum reduces the viscosity of the oil present therein and assists flow of the oil to the producer well. Steam is also employed in a so-called "steam stimulation" or "huff-and-puff" technique, in which steam is injected for a prolonged period down a single well until the oil-bearing stratum is heated and pressurized, and thereafter the injection of steam is discontinued and an oil/water mixture allowed to flow out of the same well by which the steam was injected.
Unfortunately, various segments within formations containing oil-bearing strata often differ greatly in fluid permeability. Fractures frequently occur within oil-bearing strata either naturally occurring or due to fracturing which is normally effected near the bottom of a producer well in order to assist oil flow during the initial phase of oil recovery. In addition, there may be naturally occurring segments or streaks of high permeability present in the oil-bearing strata, such as segments of loosely-packed sand. When such high permeability segments are present, flow of flooding fluid occurs preferentially along these segments and therefore, after a short period of flooding, almost all of the liquid recovered from the producer well will comprise flooding fluid with only small proportions of oil. Thus, fluid handling facilities have to be increased while significant amounts of displaceable oil in segments of low fluid permeability are by-passed. The poor sweep efficiencies induced by the unfavorable flow through segments of high fluid permeability have thus greatly inhibited the efficiency of secondary recovery processes.
In addition to the aforementioned problems caused by high fluid permeability segments in the oil-bearing strata themselves, difficulties can be caused by high permeability segments lying outside the oil-bearing strata but within the same formation. In particular, water-bearing segments can cause problems during recovery of oil by the aforementioned huff-and-puff technique. If an oil-bearing stratum contained a very viscous crude oil requiring steam extraction is disposed adjacent a water-saturated layer, a large proportion of the steam injected may be absorbed by the water-saturated layer rather than by the oil-bearing stratum, and this absorption of steam by the water-saturated layer in effect wastes the steam and results in very low proportions of oil in the oil/water mixture recovered by the huff-and-puff technique.
In attempting to overcome the aforementioned problems caused by high fluid permeability segments within the formation containing the oil-bearing stratum, it is known to inject into the formation solutions which at least partially plug the high fluid permeability segments, thereby greatly decreasing the permeability of these segments so that flooding fluid injected thereafter is forced to traverse other segments in the oil-bearing stratum, or is prevented from entering the water-saturated stratum, thus leading to increased recovery. When separate producer and injector wells are used, the liquids used to plug the high permeability segments are usually injected via the injector well, but may also be injected via the producer well if necessary. For example, U.S. Pat. No. 3,396,790, issued Aug. 13, 1968 to Eaton, proposes a method of plugging high fluid permeability segments in which water is first injected into a well at a high rate, then a viscous solution comprising sodium silicate, polyacrylamide and water is injected. After the injection of the viscous solution, water is again injected at a high rate and under high pressure, followed by injection of a less viscous solution containing ferrous sulfate and water. By carefully controlling the pressure and injection rates of the viscous and ferrous sulfate solutions, the two solutions react together to form plugs in the high permeability segments.
U.S. Pat. No. 3,749,172, issued July 31, 1973 to Hessert et al, proposes a similar procedure for plugging high permeability segments, but in which the plugging solution contains a polymeric gel.
U.S. Pat. No. 3,882,938, issued May 13, 1975 to Bernard describes a plugging technique involving the injection into the oil-bearing stratum of one or more aqueous solutions of reagents that react within the oil-bearing stratum to form a silicate and a gelling agent such as an acid, an ammonium salt, a lower aldehyde, a polyvalent metal salt or an alkali metal aluminate.
U.S. Pat. No. 3,897,827, issued Aug. 5, 1975 to Felber et al, describes a gel forming solution consisting of a dichromate activator and a lignosulfonate solution containing an alkali metal or alkaline earth metal halide
U.S. Pat. No. 3,583,586, issued June 8, 1971 to Stratton, describes a plugging solution containing an ethoxylated condensation produce of a phenol and formaldehyde.
U.S. Pat. No. 4,074,757, issued Feb. 21, 1978 to Felber et al, describes gelation of solutions containing sodium or ammonium lignosulfonate in fresh water or brine at temperatures greater than 250.degree. F. (120.degree. C.) without the addition of any other gelation-promoting agents. Similarly Canadian Patent 1,041,900 issued Dec. 7, 1978 (and U.S. Pat. No. 3,987,827) describes gelation of lignosulfonate solutions containing 2-20 percent reducing sugars at 250.degree. F. (120.degree. C.) and the use of such lignosulfonate solutions as diverting agents in strata undergoing steam flooding.
U.S. Pat. No. 4,091,868, issued May 30, 1978 to Kozlowski et al, describes processes for plugging oil producing formations using compositions containing a precatalyzed resin which sets to a water-impermeable gel: the preferred resin for use in this process is a polyphenolic-paraformaldehyde resin.
U.S. Pat. No. 4,275,789, issued June 30, 1981 to Felber et al, describes the use of solutions containing lignosulfonate and sodium silicate, having total solids contents of from 2 to 10 percent by weight and silicate: lignosulfonate weight ratios of 0.2 to 1, to selectively plug high permeability zones in strata.
U.S. Pat. No. 4,212,747, issued July 15, 1980 to Swanson, proposes as a plugging solution a shear thickening polymer composition containing a high molecular weight polyalkylene oxide polymer with phenol/aldehyde resin, the composition being alkaline.
U.S. Pat. No. 4,246,124, issued Jan. 20, 1981 to Swanson, describes an aqueous plugging solution containing a water-dispersible polymer, an aldehyde and a phenolic compound, which may either be a simple phenol or a tannin such as quebracho or sulfomethylated quebracho.
The wide variety of operating conditions encountered during enhanced recovery of oil, which are due in no small part to the highly diversified physical and chemical character of oil deposits in North America and throughout the world, dictate that any composition for plugging segments of high fluid permeability within formations containing oil-bearing strata meet numerous operating requirements. A principal requirement of an effective plugging solution is that its reactivity be sufficiently controllable to plug the high permeability segments in an operationally-feasible gel time over the wide temperature ranges routinely encountered during various conventional recovery procedures. These temperatures may range from 10.degree. to 250.degree. C. Once formed, the gel should also be resistant to all conventional flooding liquids, some of which may be used at elevated temperatures, and to steam injected to recover viscous oil from the oil-bearing stratum; this steam may be superheated to temperatures of at least 315.degree. C. or more. In order that the plugging solution may be pumped down a deep well by which it is injected and for a considerable distance thereafter into the high fluid permeability segment, the plugging solution should have a low viscosity when first formulated and should remain of low viscosity for an extended period of time (which may vary from several hours to several weeks) to allow its flow into the high fluid permeability segment. Thereafter, the plugging solution should rapidly gel to give a gel of high mechanical strength. It is particularly desirable to have plugging solutions which can be tailored by the operator by (1) selection of a particular agent which gives optimum performance over the anticipated operating temperature range and (2) by varying the relative amounts of the components in the plugging solution to give a desired time lag before gelling of the solution occurs. It is also sometimes desirable to produce only a reduction in permeability of the high permeability segments and therefore the operator should be able to control the composition of the plugging solution in such a manner as to allow only partial plugging of the high permeability zones. In addition, the plugging solution should not be affected by shear forces to which it is often subjected during pumping into porous high fluid permeability segments.
The plugging solution should, of course, also not be adversely affected by various conditions which may be present within the high fluid permeability segment. Since the high permeability segments to be plugged are often still wet with oil, the plugging solution must be able to gel in the presence of residual oil, especially in the presence of oil-wet sandstone often encountered in oil-bearing strata, and the gel must be stable in the presence of such oil. Also, many oil-bearing strata, or water-saturated layers present adjacent oil-bearing strata, contain brine of various concentrations, and accordingly, the plugging solution should be able to gel in the presence of brine and the formed gel should not deteriorate during prolonged exposure to brine.
Not only should the plugging solution be resistant to the effects of, and able to gel in the presence of, brine within the high fluid permeability segments to be plugged, but from a practical point of view it is important that the components of the plugging solution be such that the solution can be made up using brackish water or brine. For obvious economic reasons, plugging solutions are normally aqueous and many oil wells are located in remote areas. In order to avoid shipping tons of fresh water to such remote sites, it is obviously highly desirable that one be able to make up the plugging solution using whatever water is available at the drilling site, and frequently the only large sources of water which are available are either brackish, or comprise the brine which has previously been removed from the well, when the drilling site is on land. In many cases today, the drilling site may be off-shore, where the problem of transporting large quantities of fresh water to the drilling site is of course exacerbated under off-shore conditions where the only large readily available source of water is seawater. Thus, it is desirable that a gelling solution have the capability to be made up using either brine or seawater as the aqueous medium.
Prior art plugging solutions have not been successful in meeting all of the stringent operational requirements discussed above. Many prior art plugging solutions have been so viscous that it is difficult to pump them with sufficient speed to penetrate deeply into the high permeability segments prior to gelling. This susceptibility for at least partial premature gelling has made control of the time delay before gelling occurs extremely difficult and could result in plugging of the well by which the plugging solution was being injected. Moreover, many prior art plugging solutions, especially those based on high molecular weight polymers which are subject to physical degradation by pumping shear forces, have been found to produce insufficient mechanical strength in the gel and have often exhibited poor gel performance in the presence of brine and residual oil. Hitherto, no prior art plugging solution has provided a method for controlling the rate of gellation of the plugging and solution employed which is effective over the whole temperature range which may be encountered in the field, even when the plugging solution is formulated using brine and/or sea water as the aqueous base. Furthermore, many prior art plugging solutions are greatly affected by the pH conditions under which they are required to gel within the high fluid permeability segment. Ideally, a plugging solution should perform in the same manner irrespective of the pH of the solution. More realistically, a plugging solution should not be unduly susceptible to pH and should be able to perform in a predictable manner over a wide pH range, including parts of both the acidic and basic ranges, in order that the plugging solution can be used under a broad range of reservoir conditions without undue variations in its properties.
Our co-pending applications Nos. 398,179 now abandoned and 441,430 now abandoned filed Mar. 11, 1982 and Nov. 18, 1983 respectively disclose plugging solutions and methods for their use which rely upon cross-linking of vegetable materials by formaldehyde or derivatives thereof. The compositions disclosed in application No. 398,179 use as the vegetable material a polyphenolic tannin extract, a catechin or an alkaline extract of a coniferous tree bark, and are intended for use at relatively low temperatures, typically no higher than about 65.degree. C. The compositions disclosed in application 441,430 use as the vegetable material a lignin extract derived as a by-product of the separation of cellulosics from ligninous material in the pulping process of manufacturing paper products, and are primarily intended for use at somewhat higher temperatures, up to about 150.degree. C. The plugging solutions described in these co-pending applications are more successful than previous prior art compositions in overcoming most of the problems discussed above. In particular, these plugging solutions will gel in the presence of relatively high concentrations of dissolved salts, and can thus be used in underground strata which contain brines. However, although the two aforementioned co-pending applications do suggest that the plugging solutions disclosed therein may be formulated using water containing dissolved salts, the plugging solutions disclosed in these two pending applications are not well suited for formulation with brines such as seawater. Although the plugging solutions will gel in the presence of concentrations of brine up to about that of seawater, the pH of the plugging solution is sufficiently high (at least 9) that the presence of any significant concentrations of calcium and magnesium cations in the plugging solution causes precipitation of calcium and magnesium hydroxide into the solution. Thus, if one attempts to formulate these plugging solutions using brine or seawater, precipitation of calcium and magnesium hydroxides will occur as soon as the plugging solution is formulated, and the plugging solution entering the well by which it is to be injected into the underground strata will be a heterogeneous, two-phase system comprising the metal hydroxide suspended in a liquid solution. As is well known to those skilled in the art, it is undesirable to have precipitates present in plugging solutions prior to injection (even though such precipitates will not prevent gelling of the plugging solution), since, for example, the presence of the precipitates in the solution may cause difficulties as the plugging solution is forced through porous strata to the location where it is intended to gel.
There is thus a need for compositions and methods for plugging high fluid permeability segments in formations containing oil-bearing strata, which compositions and methods can be used in segments over a temperature range of about 10.degree. C., which permit the solutions employed to be made up in brines or seawater without causing formation of precipitates in the plugging solution prior to its injection into the strata, and which produce gels stable at temperatures up to 300.degree. C. This invention seeks to provide such composition and methods.